When an oil well is first drilled and completed, the fluids (such as crude oil) may be under natural pressure that is sufficient to produce on its own. In other words, the oil rises to the surface without any assistance.
In many oil wells, and particularly those in fields that are established and aging, natural pressure has declined to the point where the oil must be artificially lifted to the surface. Subsurface, or downhole, pumps are located down in the well below the level of the oil. A string of sucker rods extends from the pump up to the surface to a pump jack device, or beam pump unit (see FIG. 1). A prime mover, such as a gasoline or diesel engine, or an electric motor, or a gas engine on the surface causes the pump jack to rock back and forth, thereby moving the string of sucker rods up and down inside of the well tubing.
The string of sucker rods operates the subsurface pump. A typical pump (see FIG. 2) has a plunger that is reciprocated inside of a barrel by the sucker rods. The barrel has a standing one-way valve, while the plunger has a traveling one-way valve, or in some pumps the plunger has a standing one-way valve, while the barrel has a traveling one-way valve. Reciprocation charges a chamber between the valves with fluid and then lifts the fluid up the tubing toward the surface.
The chamber between the standing and traveling valves is referred to as the compression chamber. The standing and traveling valves open and close by differential pressure. For example, when the plunger is dropped (the downstroke), the fluid in the compression chamber is pressurized by the plunger. The fluid in the compression chamber cannot escape by way of the standing valve, because of the one-way nature of the standing valve. The only escape for the fluid in the compression chamber is through the traveling valve. However, in order to open the traveling valve, the fluid in the compression chamber must be pressurized sufficiently to overcome the pressure of the fluid above the traveling valve.
In a well that produces both liquid and gas, the pump can become gas locked. In a gas locked pump, the compression chamber contains enough gas to act as a shock absorber, resulting in insufficient differential pressure to open the traveling valve. When gas locked, the pump reciprocates without pumping any fluid.
In the prior art, pin end plungers, (which have a pin formed by exterior threads at the plunger lower end as shown in FIG. 3), or box end plungers with external valves (see FIG. 4) are used to minimize gas locking. These plungers use a valve generally attached to the bottom of the plunger. This attached valve introduces uncompressible volumes into the compression chamber, which uncompressible volumes are located around the valve, around the seat plug and internal of the seat plug. These uncompressible volumes make it more difficult to achieve a high compression ratio in order to overcome gas locking.
In another form of the prior art, a box end plunger (see FIG. 4A) is configured with an internal valve comprised of an insert, ball, seat, o-ring, spacer, and seat retainer. This arrangement is an improvement over the other prior art but still introduces unnecessary, uncompressible compression chamber volume in the spacer and the external turned-down length at each end of the plunger. These volumes also make it more difficult to achieve a high compression ratio in order to overcome gas locking.
Thus, there is a need for a high compression pump that can operate in gas locked wells.